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UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
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FORM 10-Q
(Mark One)
[X] QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d)
OF THE SECURITIES EXCHANGE ACT OF 1934
FOR THE QUARTERLY PERIOD ENDED MARCH 31, 1999
OR
[ ] TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d)
OF THE SECURITIES EXCHANGE ACT OF 1934
FOR THE TRANSITION PERIOD FROM TO
COMMISSION FILE NUMBER 1-14365
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EL PASO ENERGY CORPORATION
(Exact Name of Registrant as Specified in its Charter)
<TABLE>
<S> <C>
DELAWARE 76-0568816
(State or Other Jurisdiction (I.R.S. Employer
of Incorporation or Organization) Identification No.)
EL PASO ENERGY BUILDING
1001 LOUISIANA STREET 77002
HOUSTON, TEXAS (Zip Code)
(Address of Principal Executive Offices)
</TABLE>
Registrant's Telephone Number, Including Area Code: (713) 420-2131
Indicate by check mark whether the registrant (1) has filed all reports
required to be filed by Section 13 or 15(d) of the Securities Exchange Act of
1934 during the preceding 12 months (or for such shorter period that the
registrant was required to file such reports), and (2) has been subject to such
filing requirements for the past 90 days. Yes [X] No [ ]
Indicate the number of shares outstanding of each of the issuer's classes
of common stock, as of the latest practicable date.
Common Stock, par value $3.00 per share. Shares outstanding on May 10,
1999: 121,491,576
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GLOSSARY
The following abbreviations, acronyms, or defined terms used in this Form
10-Q are defined below:
<TABLE>
<CAPTION>
DEFINITIONS
-----------
<S> <C>
ALJ................... Administrative Law Judge
Company............... El Paso Energy Corporation and its subsidiaries
Court of Appeals...... United States Court of Appeals for the District of Columbia Circuit
EBIT.................. Earnings before interest expense and income taxes, excluding affiliated
interest income
Edison................ Southern California Edison Company
EPA................... United States Environmental Protection Agency
EPEC.................. El Paso Energy Corporation, unless the context otherwise requires
EPFS.................. El Paso Field Services Company, a wholly owned subsidiary of El Paso
Tennessee Pipeline Co.
EPNG.................. El Paso Natural Gas Company, a wholly owned subsidiary of El Paso Energy
Corporation
EPTPC................. El Paso Tennessee Pipeline Co., a direct subsidiary of El Paso Energy
Corporation
FERC.................. Federal Energy Regulatory Commission
GSR................... Gas supply realignment
PCB(s)................ Polychlorinated biphenyl(s)
PLN................... Perusahaan Listrik Negara, the Indonesian government-owned electric
utility
PRP(s)................ Potentially responsible party(ies)
TGP................... Tennessee Gas Pipeline Company, a wholly owned subsidiary of El Paso
Tennessee Pipeline Co.
TransAmerican......... TransAmerican Natural Gas Corporation
</TABLE>
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PART I -- FINANCIAL INFORMATION
ITEM 1. FINANCIAL STATEMENTS
EL PASO ENERGY CORPORATION
CONDENSED CONSOLIDATED STATEMENTS OF INCOME
(IN MILLIONS, EXCEPT PER COMMON SHARE AMOUNTS)
(UNAUDITED)
<TABLE>
<CAPTION>
FIRST QUARTER
ENDED MARCH 31,
-------------------
1999 1998
------- -------
<S> <C> <C>
Operating revenues.......................................... $ 1,494 $ 1,619
------- -------
Operating expenses
Cost of gas and other products............................ 1,068 1,209
Operation and maintenance................................. 183 180
Depreciation, depletion, and amortization................. 71 65
Taxes, other than income taxes............................ 27 24
------- -------
1,349 1,478
------- -------
Operating income............................................ 145 141
------- -------
Other (income) and expense
Interest and debt expense................................. 73 64
Other -- net.............................................. (45) (22)
------- -------
28 42
------- -------
Income before income taxes, minority interest, and
cumulative effect of accounting change.................... 117 99
Income tax expense.......................................... 40 35
Minority interest
Preferred stock dividend requirement of subsidiary........ 6 6
------- -------
Income before cumulative effect of accounting change........ 71 58
Cumulative effect of accounting change, net of income tax... (13) --
------- -------
Net income.................................................. $ 58 $ 58
======= =======
Comprehensive income........................................ $ 49 $ 57
======= =======
Basic earnings per common share
Income before cumulative effect of accounting change...... $ 0.62 $ 0.50
Cumulative effect of accounting change, net of income
tax.................................................... (0.12) --
------- -------
Net income................................................ $ 0.50 $ 0.50
======= =======
Diluted earnings per common share
Income before cumulative effect of accounting change...... $ 0.58 $ 0.48
Cumulative effect of accounting change, net of income
tax.................................................... (0.10) --
------- -------
Net income................................................ $ 0.48 $ 0.48
======= =======
Basic average common shares outstanding..................... 116.0 115.9
======= =======
Diluted average common shares outstanding................... 127.8 121.7
======= =======
Dividends declared per common share......................... $ 0.20 $ 0.19
======= =======
</TABLE>
The accompanying Notes are an integral part of these
Condensed Consolidated Financial Statements.
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EL PASO ENERGY CORPORATION
CONDENSED CONSOLIDATED BALANCE SHEETS
(IN MILLIONS, EXCEPT SHARE AMOUNTS)
ASSETS
<TABLE>
<CAPTION>
MARCH 31, DECEMBER 31,
1999 1998
----------- ------------
(UNAUDITED)
<S> <C> <C>
Current assets
Cash and temporary investments............................ $ 90 $ 90
Accounts and notes receivable, net........................ 780 733
Materials and supplies.................................... 48 49
Other..................................................... 305 337
------- -------
Total current assets.............................. 1,223 1,209
Property, plant, and equipment, net......................... 7,191 7,220
Investments in unconsolidated affiliates.................... 973 600
Other....................................................... 1,079 1,009
------- -------
Total assets...................................... $10,466 $10,038
======= =======
LIABILITIES AND STOCKHOLDERS' EQUITY
Current liabilities
Accounts payable.......................................... $ 599 $ 724
Short-term borrowings (including current maturities of
long-term debt)........................................ 736 812
Other..................................................... 600 595
------- -------
Total current liabilities......................... 1,935 2,131
------- -------
Long-term debt, less current maturities..................... 3,082 2,552
------- -------
Deferred income taxes....................................... 1,589 1,564
------- -------
Other....................................................... 1,008 993
------- -------
Commitments and contingencies (See Note 4)
Company-obligated mandatorily redeemable convertible
preferred securities of El Paso Energy Capital Trust I.... 325 325
------- -------
Minority interest
Preferred stock of subsidiary............................. 300 300
------- -------
Other minority interest................................... 65 65
------- -------
Stockholders' equity
Common stock, par value $3 per share; authorized
275,000,000 shares; issued 125,529,432 and 124,434,110
shares, respectively................................... 377 373
Additional paid-in capital................................ 1,465 1,436
Retained earnings......................................... 494 460
Accumulated comprehensive income.......................... (23) (14)
Treasury stock (at cost) 4,233,028 and 4,149,099 shares,
respectively.................................... (92) (90)
Deferred compensation..................................... (59) (57)
------- -------
Total stockholders' equity........................ 2,162 2,108
------- -------
Total liabilities and stockholders' equity........ $10,466 $10,038
======= =======
</TABLE>
The accompanying Notes are an integral part of these
Condensed Consolidated Financial Statements.
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EL PASO ENERGY CORPORATION
CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS
(IN MILLIONS)
(UNAUDITED)
<TABLE>
<CAPTION>
FIRST QUARTER
ENDED
MARCH 31,
--------------
1999 1998
----- -----
<S> <C> <C>
Cash flows from operating activities
Net income................................................ $ 58 $ 58
Adjustments to reconcile net income to net cash provided
by operating activities
Depreciation, depletion, and amortization.............. 71 65
Deferred income taxes.................................. 23 24
Undistributed earnings in equity investees............. (11) (4)
Cumulative effect of accounting change, net of income
tax................................................... 13 --
Other.................................................. -- (2)
Working capital changes, net of the effect of
acquisitions........................................... 30 (54)
Other..................................................... (53) 23
----- -----
Net cash provided by operating activities......... 131 110
----- -----
Cash flows from investing activities
Capital expenditures...................................... (39) (47)
Investment in joint ventures and equity investees......... (443) (278)
Acquisition of EnCap Investments L.C...................... (36) --
Restricted cash deposited in escrow related to equity
investee............................................... (53) --
Other..................................................... 4 7
----- -----
Net cash used in investing activities............. (567) (318)
----- -----
Cash flows from financing activities
Net commercial paper borrowings (repayments).............. 354 (72)
Revolving credit borrowings............................... 220 --
Revolving credit repayments............................... (150) (45)
Long-term debt retirements................................ (21) (21)
Net proceeds from preferred securities of El
Paso Energy Capital Trust I issuance................... -- 317
Net proceeds from long-term note payable.................. 53 --
Dividends paid on common stock............................ (23) (22)
Other..................................................... 3 8
----- -----
Net cash provided by financing activities......... 436 165
----- -----
Decrease in cash and temporary investments.................. -- (43)
Cash and temporary investments
Beginning of period............................... 90 116
----- -----
End of period..................................... $ 90 $ 73
===== =====
</TABLE>
The accompanying Notes are an integral part of these
Condensed Consolidated Financial Statements.
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EL PASO ENERGY CORPORATION
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
(UNAUDITED)
1. BASIS OF PRESENTATION
The 1998 Annual Report on Form 10-K for the Company includes a summary of
significant accounting policies and other disclosures and should be read in
conjunction with this Quarterly Report on Form 10-Q. The condensed consolidated
financial statements at March 31, 1999, and for the quarters ended March 31,
1999, and 1998, are unaudited. The condensed balance sheet at December 31, 1998,
is derived from audited financial statements. These financial statements do not
include all disclosures required by generally accepted accounting principles. In
the opinion of management, all material adjustments necessary to present fairly
the results of operations for such periods have been included. All such
adjustments are of a normal recurring nature. Results of operations for any
interim period are not necessarily indicative of the results of operations for
the entire year due to the seasonal nature of the Company's businesses.
Financial statements for the previous periods include certain reclassifications
which were made to conform to current presentation. Such reclassifications have
no effect on reported net income or stockholders' equity.
Cumulative Effect of Accounting Change
In April 1998, the American Institute of Certified Public Accountants
issued Statement of Position 98-5, Reporting on the Costs of Start-Up
Activities. The statement defines start-up activities and requires start-up and
organization costs be expensed as incurred. In addition, it requires that any
such cost that exists on the balance sheet be expensed upon adoption of this
pronouncement. The Company adopted this pronouncement effective January 1, 1999,
and reported a charge of $13 million, net of income taxes, in the first quarter
of 1999 as a cumulative effect of a change in accounting principle.
2. MERGER WITH SONAT INC.
In March 1999, the Company entered into a merger agreement with Sonat Inc.
See Item 2, Management's Discussion and Analysis of Financial Condition and
Results of Operations, Recent Developments for a further discussion.
3. ACQUISITIONS
In February 1999, the Company acquired a 51 percent ownership interest in
East Asia Power Resources Corporation ("EAPRC"), a publicly traded company in
the Philippines, for approximately $70 million. Since the Company's majority
ownership is expected to be temporary, the investment is accounted for under the
equity method of accounting. EAPRC owns and operates three power generation
facilities in the Philippines and owns an interest in one power generation
facility in China, with a total generating capacity of 289 megawatts. Electric
power generated by the facilities is supplied to a diversified base of customers
including National Power Corporation, the state-owned utility, private
distribution companies and industrial users.
In March 1999, El Paso Power Holding Company purchased a 50 percent
ownership interest in CE Generation LLC. The investment of approximately $254
million is accounted for under the equity method of accounting. CE Generation
LLC owns four natural gas-fired cogeneration projects in New York, Pennsylvania,
Texas and Arizona and eight geothermal facilities near the Imperial Valley in
southern California, which are qualifying facilities under the Public Utility
Regulatory Policy Act. In addition, two additional geothermal facilities are
currently under construction in southern California. Collectively, the 14 power
projects will have a combined electric generating capacity of approximately 900
megawatts.
In March 1999, EPFS acquired EnCap Investments L.C. ("EnCap"), a Texas
limited liability company, for $52 million, net of cash acquired. The purchase
price included $17 million in Company common stock, of which $7 million is
issuable upon the occurrence of certain events. The acquisition was accounted
for as a purchase. EnCap is an institutional funds management firm specializing
in financing independent oil and gas
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producers. EnCap manages three separate institutional oil and gas investment
funds in the U.S., and serves as investment advisor to Energy Capital Investment
Company PLC, a publicly traded investment company in the United Kingdom.
In March 1999, the Company increased its ownership interest from 30 percent
to 40 percent in the Samalayuca Power project for approximately $22 million. In
addition, the Company made a $48 million equity contribution replacing equity
financing which was established in the second quarter of 1996.
4. COMMITMENTS AND CONTINGENCIES
Indonesia
The Company owns a 47.5 percent ownership interest in a power generating
plant in Sengkang, South Sulawesi, Indonesia. Under the terms of the project's
power purchase agreement, PLN purchases power from the Company in Indonesian
rupiah indexed to the U.S. dollar at the date of payment. Due to the devaluation
of the rupiah, the cost of power to PLN has significantly increased. PLN is
currently unable to pass this increase in cost on to its customers without
creating further political instability. PLN has requested financial aid from the
Minister of Finance to help ease the effects of the devaluation. PLN has been
paying the Company in rupiah indexed to the U.S. dollar at the rate in effect
prior to the rupiah devaluation, with a commitment to pay the balance when
financial aid is received. The difference between the current and prior exchange
rate has resulted in an outstanding balance due from PLN of $12 million at March
31, 1999. Recently, the Company met and discussed its situation and concerns
with the World Bank, the International Monetary Fund, the Overseas Private
Investment Corporation, and the U.S. Treasury Department in an attempt to
achieve a resolution through the Indonesian Minister of Finance. The Company met
with PLN in April 1999 to discuss payments in arrears and the terms of a
contract rationalization process proposed by PLN. The Company informed PLN that
all payments in arrears must first be received as a prerequisite to any further
discussions on contract rationalization. The Company continues to meet with PLN
on a regular basis to resolve the payment in arrears issue but has been
unsuccessful to date. The Company cannot predict with certainty the outcome of
such discussions. The total investment in the Sengkang project was approximately
$26 million at March 31, 1999. Additionally, the Company has provided specific
recourse guarantees of up to $6 million for loans from the project lenders. All
other project debt is non-recourse. The Company has political risk insurance on
the Sengkang project. The Company believes the current economic difficulties in
Indonesia will not have a material adverse effect on the Company's financial
position, results of operations, or cash flows.
Brazil
The Company owns 100 percent of a 250 megawatt power generating plant in
Manaus, Brazil. Power from the plant is currently sold under a four-year
contract to a subsidiary of Centrais Electricas do Norte do Brasil, S.A.,
("Electronorte"), denominated in Brazilian real. In January 1999, the real was
devalued. Under a provision in the contract, the Company is entitled to recover
a substantial portion of any devaluation. In April 1999, the contract with
Electronorte was amended to extend the term from four to six years. The Company
believes the current economic difficulties in Brazil will not have a material
adverse effect on the Company's financial position, results of operations, or
cash flows.
The contract for the Manaus power project provides for delay damages to be
paid to Electronorte if the specified construction schedule is not met.
Completion of the project was delayed beyond the originally scheduled completion
dates provided in the contract, and such delays have resulted in claims by
Electronorte for delay damages. The Company believes that any delay damages for
which it may ultimately be responsible will not have a material adverse effect
on the Company's financial position, results of operations, or cash flows.
Rates and Regulatory Matters
In July 1998, FERC issued a Notice of Proposed Rulemaking ("NOPR") in which
it sought comments on a wide range of initiatives to change the manner in which
short-term (less than one year) transportation markets are regulated. Among
other things, the NOPR proposes the following: (i) removing the price cap for
the short-term capacity market; (ii) establishing procedures to make pipeline
and shipper-owned capacity
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comparable; (iii) auctioning all available short-term pipeline capacity on a
daily basis with the pipeline unable to set a reserve price above variable
costs; (iv) changing policies or pipeline penalties, nomination procedures and
services; (v) increasing pipeline reporting requirements; (vi) permitting the
negotiation of terms and conditions of service; and (vii) potentially modifying
the procedures for certificating new pipeline construction. Also in July 1998,
FERC issued a Notice of Inquiry ("NOI") seeking comments on FERC's policy for
pricing long-term capacity. The Company provided comments on the NOPR and NOI in
April 1999. It is not known when FERC will act on the NOPR and NOI.
TGP -- In February 1997, TGP filed a settlement with FERC of all issues
related to the recovery of its GSR and other transition costs and related
proceedings (the "GSR Stipulation and Agreement"). In April 1997, FERC approved
the settlement. Under the terms of the GSR Stipulation and Agreement, TGP is
entitled to collect up to $770 million from its customers, $693 million through
a demand surcharge and $77 million through an interruptible transportation
surcharge. As of March 31, 1999, the demand portion had been fully collected and
$43 million of the interruptible transportation portion had been collected.
There is no time limit for collection of the interruptible transportation
surcharge portion. The terms of the GSR Stipulation and Agreement also provide
for a rate case moratorium through November 2000 (subject to certain limited
exceptions) and an escalating rate cap, indexed to inflation, through October
2005, for certain of TGP's customers. In accordance with the terms of the GSR
Stipulation and Agreement, TGP filed a GSR Reconciliation Report with FERC on
March 31, 1999. Upon approval of this report, TGP will refund approximately $14
million to its firm customers, which represents the amount collected in excess
of the $693 million recovered through the demand surcharge. TGP will also be
required to refund to firm customers amounts collected in excess of each firm
customer's share of the final transition costs based on the final GSR
Reconciliation Report which will be filed on March 31, 2001. Any future refund
is not expected to have a material adverse effect on the Company's financial
position, results of operations, or cash flows.
In December 1994, TGP filed for a general rate increase with FERC and in
October 1996, FERC approved a settlement resolving that proceeding. The
settlement included a structural rate design change that results in a larger
portion of TGP's transportation revenues being dependent upon throughput. One
party, a competitor of TGP, filed a Petition for Review of the FERC orders with
the Court of Appeals. The Court of Appeals remanded the case to FERC to respond
to the competitor's argument that TGP's cost allocation methodology deterred the
development of market centers (centralized locations where buyers and sellers
can physically exchange gas). At FERC's request, comments were filed in January
1999.
All cost of service issues related to TGP's 1991 general rate proceeding
were resolved pursuant to a settlement agreement approved by FERC in an order
which now has become final. However, cost allocation and rate design issues
remained unresolved. In July 1996, following an ALJ's decision on these cost and
design issues, FERC ruled on certain issues but remanded to the ALJ the issue of
the proper allocation of TGP's New England lateral costs. In July 1997, FERC
issued an order denying rehearing of its July 1996 order but clarifying that,
among other things, although the ultimate resolution as to the proper allocation
of costs would be applied retroactively to July 1, 1995, the cost of service
settlement does not allow TGP to recover from other customers any amounts that
TGP may ultimately be required to refund. In February 1999, petitions for review
of the July 1996 and July 1997 FERC orders were denied by the Court of Appeals.
In the remand proceeding, the ALJ issued his decision on the proper allocation
of the New England lateral costs in December 1997. That decision adopts a
methodology that economically approximates the one currently used by TGP. In
October 1998, FERC issued an order affirming the ALJ's decision and, in April
1999, FERC denied requests for rehearing of the October 1998 order.
TGP has filed cash out reports for the period September 1993 through August
1998. TGP's filings showed a cumulative loss through August of 1998 of $3
million. The reports, as well as the accounting for customer imbalances, were
previously challenged by TGP's customers. In April 1999, FERC approved a
settlement that resolved outstanding FERC proceedings relating to the filed
cashout reports, subject to rehearing. The settlement provides a new mechanism
for accounting for TGP's cash out program.
Substantially all of the revenues of TGP are generated under long-term gas
transmission contracts. Contracts representing approximately 70 percent of TGP's
firm transportation capacity will expire by
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November 2000. Although TGP cannot predict how much capacity will be
resubscribed, a majority of the expiring contracts cover service to northeastern
markets, where there is currently little excess capacity. Several projects,
however, have been proposed to deliver incremental volumes to these markets.
Although TGP is actively pursuing the renegotiation, extension and/or
replacement of these contracts, there can be no assurance as to whether TGP will
be able to extend or replace these contracts (or a substantial portion thereof)
or that the terms of any renegotiated contracts will be as favorable to TGP as
the existing contracts.
EPNG -- In June 1995, EPNG filed with FERC for approval of new system rates
for mainline transportation to be effective January 1, 1996. In March 1996, EPNG
filed a comprehensive offer of settlement to resolve that proceeding as well as
issues surrounding certain contract reductions and expirations that were to
occur from January 1, 1996, through December 31, 1997. In April 1997, FERC
approved EPNG's settlement as filed and determined that only the contesting
party, Edison, should be severed for separate determination of the rates it
ultimately pays EPNG. In July 1997, FERC issued an order denying the requests
for rehearing of the April 1997 order and the settlement was implemented
effective July 1, 1997. Hearings to determine Edison's rates were completed in
May 1998, and an initial decision was issued by the presiding ALJ in July 1998.
EPNG and Edison have filed exceptions to the decision with FERC. If the ALJ's
decision is affirmed by FERC, EPNG believes that the resulting rates to Edison
would be such that no significant, if any, refunds in excess of the amounts
reserved would be required. Pending the final outcome, Edison continues to pay
the originally filed rates, subject to refund, and EPNG continues to provide a
reserve for such potential refunds.
Edison filed with the Court of Appeals a petition for review of FERC's
April 1997 and July 1997 orders, in which it challenged the propriety of FERC's
approving the settlement over Edison's objections to the settlement as a
customer of Southern California Gas Company. In December 1998, the Court of
Appeals issued its decision vacating and remanding FERC's order. In April 1999,
FERC issued an order requiring the parties to submit briefs setting forth their
positions as to whether FERC can approve the settlement over Edison's continuing
objections. EPNG cannot predict the outcome with certainty, but it believes that
FERC will ultimately approve the settlement.
The rate settlement establishes, among other things, base rates through
December 31, 2005. Such rates escalate annually beginning in 1998. In addition,
the settlement provides for settling customers to (i) pay $295 million
(including interest) as a risk sharing obligation, which approximates 35 percent
of anticipated revenue shortfalls over an 8 year period, resulting from certain
contract reductions and expirations identified in the settlement, (ii) receive
35 percent of additional revenues received by EPNG, above a threshold, for the
same eight-year period, and (iii) have the base rates increase or decrease if
certain changes in laws or regulations result in increased or decreased costs in
excess of $10 million a year. Through March 31, 1999, approximately $231 million
of the risk sharing obligation had been paid, and the remaining balance of $64
million will be collected by the end of 2003. At March 31, 1999, the balance of
the unearned risk sharing revenue was $215 million. This amount will be
recognized ratably through the year 2003.
In addition to other arrangements to offset the effects of the reduction in
firm capacity commitments referred to above, EPNG entered into three contracts
with Dynegy Inc. ("Dynegy") for the sale of substantially all of its turned back
firm capacity available to California as of January 1, 1998, (approximately 1.3
billion cubic feet) for a two-year period beginning January 1, 1998, at rates
negotiated pursuant to EPNG's tariff provisions and FERC policies. EPNG realized
$11 million in revenue in the first quarter of 1999 and anticipates realizing at
least $32 million in revenues during the remainder of 1999. Such revenue is
subject to the revenue sharing provisions of the rate settlement. The contracts
have a transport-or-pay provision requiring Dynegy to pay a minimum charge equal
to the reservation component of the contractual charge on at least 72 percent of
the contracted volumes each month in 1999. In the third quarter of 1999, EPNG
intends to remarket this capacity pursuant to EPNG's tariff provisions and FERC
regulations, subject to Dynegy's right of first refusal.
In December 1997, EPNG filed to implement several negotiated rate
contracts, including those with Dynegy. In a protest to this filing, three
shippers (producers/marketers) requested that FERC require EPNG to eliminate
certain provisions from the Dynegy contracts, to publicly disclose and repost
the contracts for
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competitive bidding, and to suspend their effectiveness. In an order issued in
January 1998, FERC rejected several of the arguments made in the protest and
allowed the contracts to become effective as of January 1, 1998, subject to
refund, and subject to the outcome of a technical conference, which was held in
March 1998. In June 1998, FERC issued an order rejecting the protests to the
Dynegy contracts, but required EPNG to file modifications with FERC to the
contracts clarifying the credits under the reservation reduction mechanism and
the recall rights of certain capacity. In addition, EPNG agreed to separately
post capacity covered by the Dynegy contracts which becomes available in the
future. Several parties have protested EPNG's compliance filing and/or requested
rehearing of FERC's June 1998 order. In June 1998, EPNG
filed a letter agreement in compliance with the June 1998 FERC order. In
September 1998, FERC issued
an order accepting the letter agreement subject to EPNG making additional
modifications. The additional
modifications to the letter agreement required further clarification of credits
available to Dynegy under the reservation reduction mechanism and the recall
rights of certain capacity. In October 1998, EPNG filed a revised letter
agreement with FERC and requested rehearing of the September 1998 order. The
issue is pending before FERC.
Under the revenue sharing provisions of its rate case settlement, EPNG was
obligated to return approximately $12 million of non-traditional fixed cost
revenues earned in 1998 to certain customers. This amount was credited to those
customers' transportation invoices between October 1998 and March 1999. EPNG
continues to reserve for the revenue sharing provisions. At March 31, 1999, EPNG
had a reserve of $4 million for additional amounts, which are expected to be
credited to customer accounts during the period September 1999 through March
2000.
In a November 1997 order, FERC reversed its previous decision and found
that EPNG's Chaco Station should be functionalized as a gathering, not
transmission, facility and should be transferred to EPFS.
In accordance with the FERC orders, the Chaco Station was transferred to EPFS in
April 1998. EPNG
and two other parties filed petitions for review with the Court of Appeals. EPNG
and others contested FERC's functionalization ruling and other parties contested
FERC's determination of the impact of the
functionalization ruling on the treatment of the Chaco Station costs in the rate
settlement. The matter has been briefed and will be argued in September 1999.
TGP and EPNG, as interstate pipelines, are subject to FERC audits of their
books and records. EPNG currently has an open audit covering the years 1990
through 1995. FERC is expected to issue its final audit report in 1999. As part
of an industry-wide initiative, both EPNG's and TGP's property retirements are
currently under review by the FERC audit staff.
As the aforementioned rate and regulatory matters are fully and
unconditionally resolved, the Company may either recognize an additional refund
obligation or a non-cash benefit to finalize previously estimated liabilities.
Management believes the ultimate resolution of these matters, which are in
various stages of finalization, will not have a material adverse effect on the
Company's financial position, results of operations, or cash flows.
Legal Proceedings
In November 1993, TransAmerican filed a complaint in a Texas state court,
TransAmerican Natural Gas Corporation v. El Paso Natural Gas Company, et al.,
alleging fraud, tortious interference with contractual relationships, negligent
misrepresentation, economic duress, civil conspiracy, and violation of state
antitrust laws arising from a settlement agreement entered into by EPNG,
TransAmerican Natural Gas Corporation ("TransAmerican"), and others in 1990 to
settle litigation then pending and other potential claims. The complaint, as
amended, seeks actual damages of $1.5 billion and exemplary damages of $6
billion. EPNG is defending the matter in the State District Court of Dallas
County, Texas. In April 1996, a former employee of TransAmerican filed a related
case in Harris County, Texas, Vickroy E. Stone v. Godwin & Carlton, P.C., et al.
(including EPNG), seeking indemnification and other damages in unspecified
amounts relating to litigation consulting work allegedly performed for various
entities, including EPNG, in cases involving TransAmerican. EPNG filed a motion
for summary judgment in the TransAmerican case arguing that plaintiff's claims
are barred by a prior release executed by TransAmerican, by statues of
limitations, and by the final court judgment ending the original litigation in
1990. Following a hearing in January 1998, the court
8
<PAGE> 11
granted summary judgment in EPNG's favor on TransAmerican's claims based on
economic duress and negligent misrepresentation, but denied the motion as to the
remaining claims. In March 1999, the Court ruled in EPNG's favor, denying
TransAmerican's summary judgment motion which sought to dismiss EPNG's
counterclaims. In April 1999, EPNG filed a motion for partial summary judgment
as to
TransAmerican's claims of fraud, tortious interference and civil conspiracy.
That motion is currently set for hearing in June 1999. The TransAmerican trial
is set to commence in September 1999. In February 1998, EPNG filed a motion for
summary judgment in the Stone litigation arguing that all claims are baseless,
barred by statutes of limitations, subject to executed releases, or have been
assigned to TransAmerican. In June 1998, the court granted EPNG's motion in its
entirety and dismissed all the remaining claims in the Stone litigation. In
August 1998, the court denied Stone's motion for a new trial seeking
reconsideration of that ruling. Stone has appealed the court's ruling to the
Texas Court of Appeals in Houston, Texas. Based on information available at this
time, management believes that the claims asserted against it in both cases have
no factual or legal basis and that the ultimate resolution of these matters will
not have a material adverse effect on the Company's financial position, results
of operations, or cash flows.
In February 1998, the United States and the State of Texas filed in a
United States District Court a Comprehensive Environmental Response,
Compensation and Liability Act cost recovery action, United States v. Atlantic
Richfield Co., et al., against fourteen companies including the following
affiliates of EPEC: TGP, EPTPC, EPEC Corporation, EPEC Polymers, Inc. and the
dissolved Petro-Tex Chemical Corporation, relating to the Sikes Disposal Pits
Superfund Site ("Sikes") located in Harris County, Texas. Sikes was an
unpermitted waste disposal site during the 1960s that accepted waste hauled from
numerous Houston Ship Channel industries. The suit alleges that the former
Tenneco Chemicals, Inc. and Petro-Tex Chemical Corporation arranged for disposal
of hazardous substances at Sikes. TGP, EPTPC, EPEC Corporation and EPEC
Polymers, Inc. are alleged to be derivatively liable as successors or as parent
corporations. The suit claims that the United States and the State of Texas have
expended over $125 million in remediating the site, and seeks to recover that
amount plus interest. Other companies named as defendants include Atlantic
Richfield Company, Crown Central Petroleum Corporation, Occidental Chemical
Corporation, Exxon Corporation, Goodyear Tire & Rubber Company, Rohm & Haas
Company, Shell Oil Company and Vacuum Tanks, Inc. These defendants have filed
their answers and third-party complaints seeking contribution from twelve other
entities believed to be PRPs at Sikes. Although factual investigation relating
to Sikes is in very preliminary stages, the Company believes that the amount of
material, if any, disposed at Sikes from the Tenneco Chemicals, Inc. or
Petro-Tex Chemical Corporation facilities was small, possibly de minimis.
However, the government plaintiffs have alleged that the defendants are each
jointly and severally liable for the entire remediation costs and have also
sought a declaration of liability for future response costs such as groundwater
monitoring. While the outcome of this matter cannot be predicted with certainty,
management does not expect this matter to have a material adverse effect on the
Company's financial position, results of operations, or cash flows.
TGP is a party in proceedings involving federal and state authorities
regarding the past use by TGP of a lubricant containing PCBs in its starting air
systems. TGP has executed a consent order with the EPA governing the remediation
of certain of its compressor stations and is working with the relevant states
regarding those remediation activities. TGP is also working with the
Pennsylvania and New York environmental agencies to specify the remediation
requirements at the Pennsylvania and New York stations. Remediation activities
in Pennsylvania are complete with the exception of some long-term groundwater
monitoring requirements. Remediation and characterization work at the compressor
stations under its consent order with the EPA and the jurisdiction of the New
York Department of Environmental Conservation is ongoing. Management believes
that the ultimate resolution of these matters will not have a material adverse
effect on the Company's financial position, results of operations, or cash
flows.
In November 1988, the Kentucky environmental agency filed a complaint in a
Kentucky state court, Commonwealth of Kentucky, Natural Resources and
Environmental Protection Cabinet v. Tennessee Gas Pipeline Company, alleging
that TGP discharged pollutants into the waters of the state without a permit and
disposed of PCBs without a permit. The agency sought an injunction against
future discharges, sought an order to remediate or remove PCBs, and sought a
civil penalty. TGP has entered into agreed orders with the
9
<PAGE> 12
agency to resolve many of the issues raised in the original allegations, has
received water discharge permits for its Kentucky compressor stations from the
agency, and continues to work to resolve the remaining issues. The relevant
Kentucky compressor stations are scheduled to be characterized and remediated
under the consent order with the EPA. Management believes that the resolution of
this issue will not have a material adverse effect on the Company's financial
position, results of operations, or cash flows.
A number of subsidiaries of EPEC, both wholly and partially owned, have
been named defendants in actions brought by Jack Grynberg on behalf of the U.S.
Government under the false claims act. Generally, the complaints allege an
industry-wide conspiracy to underreport the heating value as well as the volumes
of the natural gas produced from federal and Indian lands, thereby depriving the
U.S. Government of royalties. In April 1999, the U.S. Government filed a notice
that it does not intend to intervene in these actions. The Company believes the
complaint to be without merit.
The Company is a named defendant in numerous lawsuits and a named party in
numerous governmental proceedings arising in the ordinary course of business.
While the outcome of such lawsuits or other proceedings against the Company
cannot be predicted with certainty, management currently does not expect these
matters to have a material adverse effect on the Company's financial position,
results of operations, or cash flows.
Environmental
The Company is subject to extensive federal, state, and local laws and
regulations governing environmental quality and pollution control. These laws
and regulations require the Company to remove or remedy the effect on the
environment of the disposal or release of specified substances at current and
former operating sites. As of March 31, 1999, the Company had reserves of
approximately $252 million for expected environmental costs.
In addition, the Company estimates that its subsidiaries will make capital
expenditures for environmental matters of approximately $6 million for the
remainder of 1999. Capital expenditures are expected to range from approximately
$84 million to $109 million in the aggregate for the years 2000 through 2007.
These expenditures primarily relate to compliance with air regulations and, to a
lesser extent, control of water discharges.
Since 1988, TGP has been engaged in an internal project to identify and
deal with the presence of PCBs and other substances of concern, including
substances on the EPA List of Hazardous Substances, at compressor stations and
other facilities operated by both its interstate and intrastate natural gas
pipeline systems. While conducting this project, TGP has been in frequent
contact with federal and state regulatory agencies, both through informal
negotiation and formal entry of consent orders, to assure that its efforts meet
regulatory requirements.
In May 1995, following negotiations with its customers, TGP filed with FERC
a Stipulation and Agreement (the "Environmental Stipulation") that establishes a
mechanism for recovering a substantial portion of the environmental costs
identified in the internal project. The Environmental Stipulation was effective
July 1, 1995. As of March 31, 1999, all amounts have been collected under the
Environmental Stipulation. Refunds may be required to the extent actual eligible
expenditures are less than estimated eligible expenditures used to determine
amounts to be collected under the Environmental Stipulation.
The Company and certain of its subsidiaries have been designated, have
received notice that they could be designated, or have been asked for
information to determine whether they could be designated as a PRP with respect
to 32 sites under the Comprehensive Environmental Response, Compensation and
Liability Act (CERCLA or Superfund) or state equivalents. The Company has sought
to resolve its liability as a PRP with respect to these Superfund sites through
indemnification by third parties and/or settlements which provide for payment of
the Company's allocable share of remediation costs. Since the clean-up costs are
estimates and are subject to revision as more information becomes available
about the extent of remediation required, and because in some cases the Company
has asserted a defense to any liability, the Company's estimate of its share of
remediation costs could change. Moreover, liability under the federal Superfund
statute is joint and
10
<PAGE> 13
several, meaning that the Company could be required to pay in excess of its pro
rata share of remediation costs. The Company's understanding of the financial
strength of other PRPs has been considered, where appropriate, in its
determination of its estimated liability as described herein. The Company
presently believes that the costs associated with the current status of such
other entities as PRPs at the Superfund sites referenced above will not have a
material adverse effect on the Company's financial position, results of
operations, or cash flows.
The Company has initiated proceedings against its historic liability
insurers seeking payment or reimbursement of costs and liabilities associated
with environmental matters. In these proceedings, the Company contends that
certain environmental costs and liabilities associated with various entities or
sites, including costs associated with former operating sites, must be paid or
reimbursed by certain of its historic insurers. The proceedings are in the
discovery stage, and it is not yet possible to predict the outcome.
It is possible that new information or future developments could require
the Company to reassess its potential exposure related to environmental matters.
The Company may incur significant costs and liabilities in order to comply with
existing environmental laws and regulations. It is also possible that other
developments, such as increasingly strict environmental laws, regulations and
enforcement policies thereunder, and claims for damages to property, employees,
other persons and the environment resulting from current or discontinued
operations, could result in substantial costs and liabilities in the future. As
such information becomes available, or other relevant developments occur,
related accrual amounts will be adjusted accordingly. While there are still
uncertainties relating to the ultimate costs which may be incurred, based upon
the Company's evaluation and experience to date, the Company believes the
recorded reserve is adequate.
For a further discussion of other environmental matters, see Legal
Proceedings above.
Other than the items discussed above, management is not aware of any other
commitments or contingent liabilities which would have a material adverse effect
on the Company's financial condition, results of operations, or cash flows.
5. SEGMENT INFORMATION
<TABLE>
<CAPTION>
SEGMENTS
FOR THE QUARTER ENDED MARCH 31, 1999
--------------------------------------------------------------------
TENNESSEE EL PASO EL PASO EL PASO EL PASO
GAS NATURAL FIELD ENERGY ENERGY
PIPELINE GAS SERVICES MARKETING INTERNATIONAL TOTAL
--------- ------- -------- --------- ------------- -------
(IN MILLIONS)
<S> <C> <C> <C> <C> <C> <C>
Revenues from external customers....... $ 201 $ 118 $ 74 $1,084 $ 17 $ 1,494
Intersegment revenues.................. 7 -- 17 2 -- 26
Operating income (loss)................ 103 56 10 5 (16) 158
EBIT................................... 113 56 16 8 3 196
Segment assets......................... 4,887 1,728 1,459 968 1,029 10,071
</TABLE>
<TABLE>
<CAPTION>
SEGMENTS
FOR THE QUARTER ENDED MARCH 31, 1998
-------------------------------------------------------------------
TENNESSEE EL PASO EL PASO EL PASO EL PASO
GAS NATURAL FIELD ENERGY ENERGY
PIPELINE GAS SERVICES MARKETING INTERNATIONAL TOTAL
--------- ------- -------- --------- ------------- ------
(IN MILLIONS)
<S> <C> <C> <C> <C> <C> <C>
Revenues from external customers........ $ 203 $ 114 $ 59 $1,227 $ 12 $1,615
Intersegment revenues................... 9 1 9 4 -- 23
Operating income (loss)................. 94 52 20 -- (7) 159
EBIT.................................... 98 52 24 -- 2 176
Segment assets.......................... 5,137 1,757 916 536 653 8,999
</TABLE>
11
<PAGE> 14
The reconciliations of EBIT to income before income taxes, minority
interest, and cumulative effect of accounting change are presented below for the
quarters ended March 31:
<TABLE>
<CAPTION>
1999 1998
----- -----
(IN MILLIONS)
<S> <C> <C>
Total EBIT for reportable segments.......................... $196 $176
Corporate expenses, net..................................... (6) (13)
Interest and debt expense................................... (73) (64)
---- ----
Income before income taxes, minority interest, and
cumulative effect of accounting change.................... $117 $ 99
==== ====
</TABLE>
6. FINANCING TRANSACTIONS
In February 1999, DeepTech International, Inc. retired its 11% senior
promissory notes due 2000 in the amount of $16 million.
The average interest rate of short-term borrowings was 5.1% and 5.8% at
March 31, 1999 and December 31, 1998, respectively. The Company had short-term
borrowings, including current maturities of long-term debt, at March 31, 1999,
and December 31, 1998, as follows:
<TABLE>
<CAPTION>
1999 1998
----- ----
(IN MILLIONS)
<S> <C> <C>
EPEC revolving credit facility.............................. $ 350 $350
Commercial paper............................................ 694 340
Other credit facilities..................................... 130 60
Current maturities of long-term debt........................ 62 62
Less amount reclassified as long-term debt.................. (500) --
----- ----
$ 736 $812
===== ====
</TABLE>
In May 1999, EPEC issued $500 million aggregate principal amount of 6.75%
Senior Notes due 2009. Proceeds of approximately $496 million, net of issuance
costs, were used to repay approximately $350 million of outstanding debt under
EPEC's revolving credit facility and the remainder was used to repay commercial
paper. As a result of this transaction, $500 million of short-term borrowings
has been reclassified and reflected as long-term debt at March 31, 1999.
7. PROPERTY, PLANT, AND EQUIPMENT
Property, plant, and equipment at March 31, 1999, and December 31, 1998,
consisted of the following:
<TABLE>
<CAPTION>
1999 1998
------ ------
(IN MILLIONS)
<S> <C> <C>
Property, plant, and equipment, at cost..................... $6,336 $6,285
Less accumulated depreciation and depletion................. 1,619 1,546
------ ------
4,717 4,739
Additional acquisition cost assigned to utility plant, net
of accumulated amortization............................... 2,474 2,481
------ ------
Total property, plant, and equipment, net................... $7,191 $7,220
====== ======
</TABLE>
Current FERC policy does not permit the Company to recover amounts in
excess of original cost allocated in purchase accounting to its regulated
operations through rates.
12
<PAGE> 15
8. EARNINGS PER SHARE
The computation of basic and diluted earnings per common share amounts are
presented below for the quarters ended March 31.
<TABLE>
<CAPTION>
1999 1998
--------------------- ---------------------
BASIC DILUTED BASIC DILUTED
-------- --------- ------- ---------
(IN MILLIONS, EXCEPT PER COMMON SHARE AMOUNTS)
<S> <C> <C> <C> <C>
Income before cumulative effect of accounting change... $ 71 $ 71 $ 58 $ 58
Interest on trust preferred securities............... -- 3 -- --
------ ------ ----- -----
Adjusted income before cumulative effect of
accounting change................................. 71 74 58 58
Cumulative effect of accounting change, net of income
tax............................................... (13) (13) -- --
------ ------ ----- -----
Net income............................................. $ 58 $ 61 $ 58 $ 58
====== ====== ===== =====
Average common shares outstanding...................... 116 116 116 116
Effect of diluted securities
Restricted stock..................................... -- 2 -- 2
Stock options........................................ -- 2 -- 3
Trust preferred securities........................... -- 8 -- 1
------ ------ ----- -----
Adjusted average common shares outstanding............. 116 128 116 122
====== ====== ===== =====
Earnings per common share
Adjusted income before cumulative effect of
accounting change................................. $ 0.62 $ 0.58 $0.50 $0.48
Cumulative effect of accounting change, net of income
tax............................................... (0.12) (0.10) -- --
------ ------ ----- -----
Net income........................................... $ 0.50 $ 0.48 $0.50 $0.48
====== ====== ===== =====
</TABLE>
9. NEW ACCOUNTING PRONOUNCEMENTS NOT YET ADOPTED
Accounting for Derivative Instruments and Hedging Activities
In June 1998, Statement of Financial Accounting Standards No. 133,
Accounting for Derivative Instruments and Hedging Activities, was issued by the
Financial Accounting Standards Board to establish accounting and reporting
standards for derivative instruments, including certain derivative instruments
embedded in other contracts, and for hedging activities. This pronouncement
requires that an entity classify all derivatives as either assets or liabilities
in the statement of financial position and measure those instruments at fair
value. If certain conditions are met, a derivative may be specifically
designated as (i) a hedge of the exposure to changes in the fair value of a
recognized asset or liability or an unrecognized firm commitment, (ii) a hedge
of the exposure to variable cash flows of a forecasted transaction, or (iii) a
hedge of the foreign currency exposure of a net investment in a foreign
operation, an unrecognized firm commitment, an
available-for-sale security or a foreign-currency-denominated forecasted
transaction. The accounting for the changes in the fair value of a derivative
depends on the intended use of the derivative and the resulting designation. The
standard is effective for all quarters in fiscal years beginning after June 15,
1999. The Company is currently evaluating the effects of this pronouncement.
13
<PAGE> 16
ITEM 2. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS
OF OPERATIONS
The information contained in Item 2 updates, and should be read in
conjunction with, information set forth in Part II, Items 7, 7A, and 8, in the
Company's Annual Report on Form 10-K for the year ended December 31, 1998, in
addition to the interim condensed consolidated financial statements and
accompanying notes presented in Item 1 of this Quarterly Report on Form 10-Q.
RECENT DEVELOPMENTS
MERGER WITH SONAT INC.
In March 1999, the Company announced it had entered into a definitive
agreement to acquire Sonat Inc. ("Sonat"). The Company entered into the second
amended and restated agreement and plan of merger effective as of March 13,
1999, (the "Merger Agreement") with Sonat pursuant to which Sonat will merge
into the Company, and the Company will issue to Sonat stockholders one share of
Company common stock for each share of Sonat common stock owned by them, and the
Company's restated certificate of incorporation will be amended to authorize the
issuance of up to 750 million shares of common stock and 50 million shares of
preferred stock. The Company and Sonat are separately holding a special meeting
of their stockholders on June 10, 1999, to consider and vote on a proposal to
approve and adopt the Merger Agreement. If the Company's stockholders approve
the Merger Agreement, the Company intends to account for the merger as a pooling
of interests. If the Company's stockholders do not approve the Merger Agreement
and Sonat's stockholders do, Sonat will instead merge with a subsidiary of the
Company, and the Company will issue a fraction of a share of Company common
stock and a fraction of a depositary share representing a fractional interest in
a new series of senior voting preferred stock of the Company for each share of
Sonat common stock. The Company and Sonat will complete the merger only if a
number of conditions are satisfied or waived, including:
- Sonat stockholders adopt the Merger Agreement;
- no law or court order prohibits the transaction;
- all waiting periods under federal antitrust laws applicable to the merger
expire or terminate;
- all other regulatory approvals are received without conditions that would
have a material adverse effect on the financial condition, results of
operations, or cash flows of the Company's and Sonat's combined
businesses; and
- attorneys for the Company and Sonat issue opinions that the merger is
expected to be tax-free.
However, we cannot assure you that the Company and Sonat will complete the
merger even if all those conditions are satisfied.
Sonat is a diversified energy holding company. It is engaged through its
subsidiaries and joint ventures in domestic oil and natural gas exploration and
production, transmission and storage of natural gas, and natural gas and power
marketing. Sonat owns interests in approximately 14,000 miles of natural gas
pipelines extending across the southeastern U.S. from Texas to South Carolina
and Florida. Also, Sonat has interests in oil and gas producing properties in
Louisiana, Texas, Oklahoma, Arkansas, Alabama, New Mexico and the Gulf of
Mexico. Sonat owns approximately 1.6 trillion cubic feet equivalent of proved
natural gas and oil reserves based on estimates as of December 31, 1998.
RESULTS OF OPERATIONS
Consolidated EBIT for the quarter ended March 31, 1999, increased 17
percent to $190 million from $163 million in the first quarter of 1998.
Variances are discussed in the segment results below.
14
<PAGE> 17
SEGMENT RESULTS
<TABLE>
<CAPTION>
FIRST QUARTER
ENDED
MARCH 31,
--------------
1999 1998
----- -----
(IN MILLIONS)
<S> <C> <C>
EARNINGS BEFORE INTEREST EXPENSE AND INCOME TAXES
Tennessee Gas Pipeline...................................... $ 113 $ 98
El Paso Natural Gas......................................... 56 52
----- -----
Regulated segments........................................ 169 150
El Paso Field Services...................................... 16 24
El Paso Energy Marketing.................................... 8 --
El Paso Energy International................................ 3 2
----- -----
Non-regulated segments.................................... 27 26
Corporate expenses, net..................................... (6) (13)
----- -----
Total EBIT................................................ $ 190 $ 163
===== =====
</TABLE>
Tennessee Gas Pipeline
<TABLE>
<CAPTION>
FIRST QUARTER
ENDED
MARCH 31,
--------------
1999 1998
----- -----
(IN MILLIONS)
<S> <C> <C>
Operating revenues.......................................... $ 208 $ 212
Operating expenses.......................................... (105) (118)
Other -- net................................................ 10 4
----- -----
EBIT...................................................... $ 113 $ 98
===== =====
</TABLE>
Operating revenues for the quarter ended March 31, 1999, were $4 million
lower than for the same period of 1998 primarily due to lower GSR revenue in
1999, a favorable customer settlement in the first quarter of 1998, and lower
miscellaneous operating revenue. The decrease was partially offset by the
favorable resolution of a regulatory issue.
Operating expenses for the quarter ended March 31, 1999, were $13 million
lower than for the same period of 1998 primarily due to lower system fuel costs
associated with operating efficiencies related to lower throughput levels, the
favorable resolution of certain regulatory issues and lower operating expenses.
Other -- net for the quarter ended March 31, 1999, was $6 million higher
than for the same period of 1998 primarily due to the favorable resolution of
regulatory and contractual issues and higher earnings from equity investments.
15
<PAGE> 18
El Paso Natural Gas
<TABLE>
<CAPTION>
FIRST QUARTER
ENDED
MARCH 31,
-------------
1999 1998
---- ----
(IN MILLIONS)
<S> <C> <C>
Operating revenues.......................................... $118 $115
Operating expenses.......................................... (62) (63)
---- ----
EBIT...................................................... $ 56 $ 52
==== ====
</TABLE>
Operating revenues for the quarter ended March 31, 1999, were $3 million
higher than for the same period of 1998 primarily due to an increase in
non-traditional revenues including revenues from the sale of capacity to Dynegy.
El Paso Field Services
<TABLE>
<CAPTION>
FIRST QUARTER
ENDED
MARCH 31,
-------------
1999 1998
---- ----
(IN MILLIONS)
<S> <C> <C>
Gathering and treating margin............................... $ 40 $ 39
Processing margin........................................... 9 14
Other margin................................................ -- 2
---- ----
Total gross margin................................ 49 55
Operating expenses.......................................... (39) (35)
Other -- net................................................ 6 4
---- ----
EBIT...................................................... $ 16 $ 24
==== ====
</TABLE>
Total gross margin for the quarter ended March 31, 1999, was $6 million
lower than for the same period of 1998 primarily due to a decrease in the
processing margin. The decrease resulted from lower liquids prices during the
first quarter of 1999 compared to the same period of 1998. The slight increase
in the gathering and treating margin primarily resulted from higher volumes
attributable to the global compression project which was completed in September
1998. This increase was offset by lower volumes attributable to the sale of the
natural gas gathering and treating assets in the Anadarko Basin in September
1998.
Operating expenses for the quarter ended in March 31, 1999, were $4 million
higher than for the same period of 1998 primarily due to an increase in
amortization expense attributable to the acquisition of DeepTech International
Inc.
Other -- net for the quarter ended March 31, 1999, was $2 million higher
than for the same period of 1998 due to additional earnings from equity
investments primarily attributable to the acquisition of DeepTech International
Inc.
16
<PAGE> 19
El Paso Energy Marketing
<TABLE>
<CAPTION>
FIRST QUARTER
ENDED
MARCH 31,
-------------
1999 1998
---- ----
(IN MILLIONS)
<S> <C> <C>
Natural gas margin.......................................... $ 17 $ 6
Power margin................................................ 2 7
---- ----
Total gross margin................................ 19 13
Operating expenses.......................................... (14) (13)
Other -- net................................................ 3 --
---- ----
EBIT...................................................... $ 8 $ --
==== ====
</TABLE>
Total gross margin for the quarter ended March 31, 1999, was $6 million
higher than for the same period of 1998. The increase in the natural gas margin
was primarily due to the income recognition from long-term natural gas
transactions closed during the quarter. The decrease in the power margin was
largely due to the first quarter 1998 income recognition from electric power
transactions, partially offset by the contribution from power generation
facilities acquired in December 1998.
Operating expenses for the quarter ended March 31, 1999, were $1 million
higher than for the same period of 1998 primarily due to expenses associated
with acquired power generation facilities.
Other -- net for the quarter ended March 31, 1999, was $3 million higher
than for the same period of 1998 primarily due to additional earnings from the
acquisition of a 50 percent ownership interest in CE Generation LLC in March
1999.
El Paso Energy International
<TABLE>
<CAPTION>
FIRST QUARTER
ENDED MARCH 31,
----------------
1999 1998
----- -----
(IN MILLIONS)
<S> <C> <C>
Operating revenues.......................................... $ 17 $ 12
Operating expenses.......................................... (33) (19)
Other -- net................................................ 19 9
---- ----
EBIT...................................................... $ 3 $ 2
==== ====
</TABLE>
Operating revenues for the quarter ended March 31, 1999, were $5 million
higher than for the same period of 1998 primarily due to the consolidation for
financial reporting purposes of the Manaus Power project in May 1998.
Operating expenses for the quarter ended March 31, 1999, were $14 million
higher than for the same period of 1998 due to the consolidation of the Manaus
Power project and an increase in general and administrative expenses primarily
attributable to higher project development costs reflecting increased
project-related activities.
Other -- net for the quarter ended March 31, 1999, was $10 million higher
than for the same period of 1998 primarily due to higher earnings from equity
investments.
Corporate expenses, net
Net corporate expenses for the quarter ended March 31, 1999, were $7
million lower than for the same period of 1998 primarily due to lower costs
related to the Company's employee incentive plans and lower benefits costs.
17
<PAGE> 20
INTEREST AND DEBT EXPENSE
Interest and debt expense for the quarter ended March 31, 1999, was $9
million higher than for the same period of 1998 primarily due to increased
borrowings used to fund acquisitions, capital expenditures, and other investing
expenditures.
INCOME TAX EXPENSE
The effective tax rate for the quarter ended March 31, 1999, was lower than
the rate for the same period of 1998 primarily as a result of increased
consolidated foreign income subject to foreign tax rates different than U.S. tax
rates and increased equity income from unconsolidated foreign affiliates
recorded net of foreign income taxes for which no provision for U.S. income tax
is required.
LIQUIDITY AND CAPITAL RESOURCES
CASH FROM OPERATING ACTIVITIES
Net cash provided by operating activities was $21 million higher for the
quarter ended March 31, 1999, compared to the same period of 1998. The increase
was primarily attributable to a take-or-pay refund to EPNG customers in February
1998 and other working capital changes. The increase was partially offset by net
income tax refunds received in 1998 and non-working capital changes including
lower GSR collections in 1999.
CASH FROM INVESTING ACTIVITIES
Net cash used in investing activities was $567 million for the quarter
ended March 31, 1999. Expenditures related to joint ventures and equity
investments were primarily for the acquisition of the 50 percent ownership
interest in CE Generation LLC, as well as the acquisition of a 51 percent
ownership interest in the East Asia Power project. Other investment activity
included the acquisition of EnCap. Internally generated funds, supplemented by
other financing activities, were used to fund these expenditures.
Future funding for capital expenditures, acquisitions, and other investing
expenditures is expected to be provided by internally generated funds,
commercial paper issuances, available capacity under existing credit facilities,
and/or the issuance of other long-term debt, trust securities, or equity.
CASH FROM FINANCING ACTIVITIES
Net cash provided by financing activities was $436 million for the quarter
ended March 31, 1999.
Short-term borrowings, supplemented by internally generated funds, were used to
fund capital and equity investments, retire long-term debt, pay dividends, and
for other corporate purposes.
The following table reflects quarterly dividends declared and paid on
EPEC's common stock:
<TABLE>
<CAPTION>
AMOUNT PER
DECLARATION DATE COMMON SHARE PAYMENT DATE TOTAL AMOUNT
---------------- ------------ ------------ -------------
(IN MILLIONS)
<S> <C> <C> <C>
October 22, 1998....................... $0.19125 January 4, 1999 $22
January 21, 1999....................... $0.20000 April 1, 1999 $23
</TABLE>
In April 1999, the board of directors of EPEC declared a quarterly dividend
of $0.20 per share on EPEC's common stock, payable on July 1, 1999, to
stockholders of record on June 4, 1999. Also during the first quarter of 1999,
quarterly dividends of $6 million were paid on the 8 1/4% cumulative preferred
stock, series A of EPTPC.
Future funding for long-term debt retirements, dividends, and other
financing expenditures is expected to be provided by internally generated funds,
commercial paper issuances, available capacity under existing credit facilities,
and/or the issuance of other long-term debt, trust securities, or equity.
18
<PAGE> 21
At March 31, 1999, the Company had approximately $450 million available
under its revolving credit facilities. The availability of borrowings under the
Company's credit agreements is subject to certain specified conditions, which
management believes it currently meets.
In May 1999, EPEC issued $500 million aggregate principal amount of 6.75%
Senior Notes due 2009. Proceeds of approximately $496 million, net of issuance
costs, were used to repay approximately $350 million of outstanding debt under
EPEC's revolving credit facility and the remainder was used to repay commercial
paper. As a result of this transaction, $500 million of short-term debt has been
reclassified and reflected as long-term debt at March 31, 1999.
COMMITMENTS AND CONTINGENCIES
See Note 4, which is incorporated herein by reference.
OTHER
PPN POWER PROJECT
In March 1999, the Company signed a sale and purchase agreement, subject to
the project lenders' consent, to acquire a 26 percent interest in a $295 million
power plant in Tamil Nadu, India. The project consists of a 346 megawatt
combined cycle power plant which will serve as a base load facility and sell
power to the state-owned Tamil Nadu Electricity Board under a thirty-year power
purchase agreement. Construction began in January 1999, and operations are
expected to commence in early 2001. The transaction is expected to close before
the end of the second quarter of 1999.
YEAR 2000
The Company has established an executive steering committee and a project
team to coordinate the phases of its Year 2000 project to assure that the
Company's key automated systems, equipment, and related processes will remain
functional through the year 2000. Those phases are: (i) awareness; (ii)
assessment; (iii) remediation; (iv) testing; (v) implementation of the necessary
modifications and (vi) contingency planning.
In recognition of the importance of Year 2000 issues and their potential
impact to the Company, the initial phase of the Year 2000 project involved the
establishment of a company-wide awareness program. The awareness program is
directed by the executive steering committee and project team and includes
participation of senior management in each core business area. The awareness
phase is substantially completed, although the Company will continually update
awareness efforts for the duration of the Year 2000 project.
The Company's assessment phase consists of conducting a company-wide
inventory of its key automated systems and related processes, analyzing and
assigning levels of criticality to those systems and processes, identifying and
prioritizing resource requirements, developing validation strategies and testing
plans, and evaluating business partner relationships. The portion of the
assessment phase related to internally developed computer applications, hardware
and equipment, third-party-developed software, and embedded chips is
substantially complete. The assessment phase of the project, among other things,
involves efforts to obtain representations and assurances from third parties,
including third party vendors, that their hardware and equipment products,
embedded chip systems, and software products being used by or impacting the
Company are or will be modified to be Year 2000 compliant. To date, the
responses from such third parties, although generally encouraging, are
inconclusive. As a result, the Company cannot predict the potential consequences
if these or other third parties or their products are not Year 2000 compliant.
The Company continues to evaluate the exposure associated with such business
partner relationships.
The remediation phase involves converting, modifying, replacing or
eliminating key automated systems identified in the assessment phase. The
testing phase involves the validation of the identified key automated systems.
The Company is utilizing test tools and written test procedures to document and
validate, as
19
<PAGE> 22
necessary, its unit, system, integration and acceptance testing. The Company
estimates that approximately one-fourth of the work of these phases remains, and
expects each to be substantially completed by mid-1999.
The implementation phase involves placing the converted or replaced key
automated systems into operation. In some cases, this phase will also involve
the implementation of contingency plans needed to support business functions and
processes that may be interrupted by Year 2000 failures that are outside of the
Company's control. The Company has completed more than three-fourths of the
implementation phase, which is expected to be substantially completed by
mid-1999.
The contingency planning phase consists of developing a risk profile of the
Company's critical business processes and then providing for actions the Company
will pursue to keep such processes operational in the event of Year 2000
disruptions. The focus of such contingency planning is on prompt response to any
Year 2000 events, and a plan for subsequent resumption of normal operations. The
plan is expected to assess the risk of a significant failure to critical
processes performed by the Company, and to address the mitigation of those
risks. The plan will also consider any significant failures related to the most
reasonably likely worst case scenario, discussed below, as they may occur. In
addition, the plan is expected to factor in the severity and duration of the
impact of a significant failure. The Company plans to have its contingency plan
completed by mid-1999. The Year 2000 contingency plan will continue to be
modified and adjusted throughout the year as additional information becomes
available.
The goal of the Year 2000 project is to ensure that all of the critical
systems and processes which are under the Company's direct control remain
functional. Certain systems and processes may be interrelated with or dependent
upon systems outside the Company's control. However, systems within the
Company's control may also have unpredicted problems. Accordingly, there can be
no assurance that significant disruptions will be avoided. The Company's present
analysis of its most reasonably likely worst case scenario for Year 2000
disruptions includes Year 2000 failures in the telecommunications and
electricity industries, as well as interruptions from suppliers that might cause
disruptions in the Company's operations, thus causing temporary financial losses
and an inability to deliver products and services to customers. Virtually all of
the natural gas transported through the Company's interstate pipelines is owned
by third parties. Accordingly, failures of natural gas producers to be ready for
the Year 2000 could significantly disrupt the flow of product to the Company's
customers. In many cases, the producers have no direct contractual relationship
with the Company, and the Company relies on its customers to verify the Year
2000 readiness of the producers from whom they purchase natural gas. Since most
of the Company's revenues from the delivery of natural gas are based upon fees
paid by its customers for the reservation of capacity, and not based upon the
volume of actual deliveries, short term disruptions in deliveries caused by
factors beyond the Company's control should not have a significant financial
impact on the Company, although it could cause operational problems for the
Company's customers. Longer-term disruptions, however, could materially impact
the Company's results of operations, financial condition, and cash flows.
While the Company owns or controls most of its domestic facilities and
projects, nearly all of the Company's international investments have been made
in conjunction with unrelated third parties. In many cases, the operators of
such international facilities are not under the sole or direct control of the
Company. As a consequence, the Year 2000 programs instituted at some of the
international facilities may be different from the Year 2000 program implemented
by the Company domestically, and the party responsible for the results of such
program may not be under the direct or indirect control of the Company. In
addition, the "non-controlled" programs may not provide the same degree of
communication, documentation and coordination as the Company achieves in its
domestic Year 2000 program. Moreover, the regulatory and legal environment in
which such international facilities operate makes analysis of possible
disruption and associated financial impact difficult. Many foreign countries
appear to be substantially behind the United States in addressing potential Year
2000 disruption of critical infrastructure and in developing a framework
governing the reporting requirements and relative liabilities of business
entities. Accordingly, the Year 2000 risks posed by international operations as
a whole are different than those presented domestically. As part of its Year
2000 effort, the Company is assessing the differences between the non-controlled
programs and its domestic Year 2000 project, and has formulated and instituted a
program for identifying such risks and preparing a response to such risks. While
the Company believes that most of the international facilities in which it has
significant
20
<PAGE> 23
investments are addressing Year 2000 issues in an adequate manner, it is
possible that some of them may experience significant Year 2000 disruption, and
that the aggregate effect of problems experienced at multiple international
locations may be material and adverse. The Company is incorporating this
possibility into the relevant contingency plans.
While the total cost of the Company's Year 2000 project continues to be
evaluated, the Company estimates that the costs remaining to be incurred in 1999
and 2000 associated with assessing, remediating and testing internally developed
computer applications, hardware and equipment, embedded chip systems, and
third-party-developed software will be between $12 million and $19 million. Of
these estimated costs, the Company expects between $5 million and $9 million to
be capitalized and the remainder to be expensed. As of March 31, 1999, the
Company has incurred expenses of approximately $8 million and has capitalized
costs of approximately $2 million. The Company has previously only traced
incremental expenses related to its Year 2000 project. This means that the costs
of the Year 2000 project related to salaried employees of the Company, including
their direct salaries and benefits, are not available, and have not been
included in the estimated costs of the project. Since the earlier phases of the
project mostly involved work performed by such salaried employees, the costs
expended to date do not reflect the percentage completion of the project. The
Company anticipates that it will expend most of the costs reported above in the
remediation, implementation and contingency planning phases of the project. As
described herein, the Company and Sonat have entered into an agreement which, if
approved, will result in the merger of the Company and Sonat. If the merger is
consummated, Sonat's Year 2000 risks, liabilities and expenses will be assumed
by the Company. Based on its due diligence investigation in connection with the
merger, the Company is not aware of any material Year 2000 risks, liabilities,
or expenses that are not disclosed in Sonat's filings with the U.S. Securities
and Exchange Commission. It is possible the Company may need to reassess its
estimate of Year 2000 costs in the event the Company completes an acquisition
of, or makes a material investment in, substantial facilities or another
business entity.
Although the Company does not expect the costs of its Year 2000 project to
have a material adverse effect on its financial position, results of operations,
or cash flows, based on information available at this time the Company cannot
conclude that disruption caused by internal or external Year 2000 related
failures will not have such an effect. Specific factors which might affect the
success of the Company's Year 2000 efforts and the frequency or severity of a
Year 2000 disruption or the amount of expense include the failure of the Company
or its outside consultants to properly identify deficient systems, the failure
of the selected remedial action to adequately address the deficiencies, the
failure of the Company or its outside consultants to complete the remediation in
a timely manner (due to shortages of qualified labor or other factors), the
failure of other parties to joint ventures in which the Company is involved to
meet their obligations, both financial and operational, under the relevant joint
venture agreements to remediate assets used by the joint venture, unforeseen
expenses related to the remediation of existing systems or the transition to
replacement systems, the failure of third parties to become Year 2000 compliant
or to adequately notify the Company of potential noncompliance and the effects
of any significant disruption at international facilities in which the Company
has significant investments.
The above disclosure is a "YEAR 2000 READINESS DISCLOSURE" made with the
intention to comply fully with the Year 2000 Information and Readiness
Disclosure Act of 1998, Pub. L. No. 105-271, 112 Stat, 2386, signed into law
October 19, 1998. All statements made herein shall be construed within the
confines of that Act. To the extent that any reader of the above Year 2000
Readiness Disclosure is other than an investor or potential investor in the
Company's -- or an affiliate's -- equity or debt securities, this disclosure is
made for the SOLE PURPOSE of communicating or disclosing information aimed at
correcting, helping to correct and/or avoiding Year 2000 failures.
NEW ACCOUNTING PRONOUNCEMENTS NOT YET ADOPTED
See Note 9, which is incorporated herein by reference.
21
<PAGE> 24
CAUTIONARY STATEMENT FOR PURPOSES OF THE "SAFE HARBOR" PROVISIONS OF
THE PRIVATE SECURITIES LITIGATION REFORM ACT OF 1995.
This report contains forward-looking statements within the meaning of the
Private Securities Litigation Reform Act of 1995. Where any such forward-looking
statement includes a statement of the assumptions or bases underlying such
forward-looking statement, the Company cautions that, while such assumptions or
bases are believed to be reasonable and are made in good faith, assumed facts or
bases almost always vary from the actual results, and the differences between
assumed facts or bases and actual results can be material, depending upon the
circumstances. Where, in any forward-looking statement, the Company or its
management expresses an expectation or belief as to future results, such
expectation or belief is expressed in good faith and is believed to have a
reasonable basis, but there can be no assurance that the statement of
expectation or belief will result or be achieved or accomplished. The words
"believe," "expect," "estimate," "anticipate" and similar expressions may
identify forward-looking statements.
Important factors that could cause actual results to differ materially from
those in the forward-looking statements herein include increasing competition
within the Company's industry, the timing and extent of changes in commodity
prices for natural gas and power, uncertainties associated with acquisitions and
joint ventures, potential environmental liabilities, potential contingent
liabilities and tax liabilities related to the Company's acquisitions, political
and economic risks associated with current and future operations in foreign
countries, conditions of the equity and other capital markets during the periods
covered by the forward-looking statements, and other risks, uncertainties and
factors, including the effect of the Year 2000 date change, discussed more
completely in the Company's other filings with the U.S. Securities and Exchange
Commission, including its Annual Report on Form 10-K for the year ended December
31, 1998.
ITEM 3. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK
The information contained in Item 3 updates, and should be read in
conjunction with, information set forth in Part II, Item 7A in the Company's
Annual Report on Form 10-K for the year ended December 31, 1998, in addition to
the interim consolidated financial statements, accompanying notes, and
Management's Discussion and Analysis of Financial Condition and Results of
Operations presented in Items 1 and 2 of this Quarterly Report on Form 10-Q.
There are no material changes in market risks faced by the Company from
those reported in the Company's Annual Report on Form 10-K for the year ended
December 31, 1998.
22
<PAGE> 25
PART II -- OTHER INFORMATION
ITEM 1. LEGAL PROCEEDINGS
See Part I, Financial Information, Note 4, which is incorporated herein by
reference.
ITEM 2. CHANGES IN SECURITIES AND USE OF PROCEEDS
None.
ITEM 3. DEFAULTS UPON SENIOR SECURITIES
None.
ITEM 4. SUBMISSION OF MATTERS TO A VOTE OF SECURITY-HOLDERS
None.
ITEM 5. OTHER INFORMATION
None.
ITEM. 6. EXHIBITS AND REPORTS ON FORM 8-K
a. Exhibits
Each exhibit identified below is filed as part of this report. Exhibits
designated with a "+" constitute a management contract or compensatory plan or
arrangement required to be filed as an exhibit to this report.
<TABLE>
<CAPTION>
EXHIBIT
NUMBER DESCRIPTION
------- -----------
<C> <S>
+10.E.1 -- Amendment No. 1, effective March 9, 1999, to the 1995
Compensation Plan for Non-Employee Directors, Amended and
Restated effective as of August 1, 1998.
27 -- Financial Data Schedule.
</TABLE>
Undertaking
The undersigned hereby undertakes, pursuant to Regulation S-K, Item
601(b), paragraph (4)(iii), to furnish to the U.S. Securities and Exchange
Commission, upon request, all constituent instruments defining the rights
of holders of long-term debt of EPEC and its consolidated subsidiaries not
filed herewith for the reason that the total amount of securities
authorized under any of such instruments does not exceed 10 percent of the
total consolidated assets of EPEC and its consolidated subsidiaries.
b. Reports on Form 8-K
EPEC filed a report under Item 5 and Item 7 on Form 8-K, dated March 15,
1999, with respect to the Sonat Merger Agreement. In addition, EPEC filed a
report under Item 5 and Item 7 on Form 8-K and Form 8-K/A dated April 23, 1999
and April 30, 1999, respectively, disclosing preliminary unaudited pro forma
financial information of EPEC and Sonat giving effect to the proposed merger.
EPEC filed a report under Item 5 and Item 7 on Form 8-K, dated May 10, 1999
with respect to the issuance of $500 million aggregate principal amount of 6.75%
Senior Notes due 2009.
23
<PAGE> 26
SIGNATURES
Pursuant to the requirements of the Securities Exchange Act of 1934, the
Registrant has duly caused this report to be signed on its behalf by the
undersigned thereunto duly authorized.
EL PASO ENERGY CORPORATION
Date: May 12, 1999 /s/ H. BRENT AUSTIN
------------------------------------
H. Brent Austin
Executive Vice President and
Chief Financial Officer
Date: May 12, 1999 /s/ JEFFREY I. BEASON
------------------------------------
Jeffrey I. Beason
Vice President and Controller
(Chief Accounting Officer)
24
<PAGE> 27
INDEX TO EXHIBITS
Each exhibit identified below is filed as part of this report. Exhibits
designated with a "+" constitute a management contract or compensatory plan or
arrangement required to be filed as an exhibit to this report.
<TABLE>
<CAPTION>
EXHIBIT
NUMBER DESCRIPTION
------- -----------
<C> <S>
+10.E.1 -- Amendment No. 1, effective March 9, 1999, to the 1995
Compensation Plan for Non-Employee Directors, Amended and
Restated effective as of August 1, 1998.
27 -- Financial Data Schedule.
</TABLE>
25
<PAGE> 1
EXHIBIT 10.E.1
AMENDMENT NO. 1 TO THE
1995 COMPENSATION PLAN
FOR NON-EMPLOYEE DIRECTORS
Pursuant to Section 8.7 of the El Paso Energy Corporation 1995
Compensation Plan for Non-Employee Directors, Amended and Restated Effective as
of August 1, 1998 (the "Plan"), the Plan is hereby amended as follows, effective
March 9, 1999:
Section 6.7(b) is amended to read as follows:
"(b) All deferred cash and deferred Common Stock under this
Plan shall be paid to a Participant (or his or her Beneficiary in the
case of his or her death) in the event of a Change in Control within
thirty (30) days after the date of the Change in Control, or at such
later time as may be required to enable the Director to avoid liability
under Section 16(b) of the Exchange Act. Notwithstanding the foregoing,
no such deferred amounts shall be paid to a Participant who continues
to serve as a Director of the Company or its successor, until such time
said deferrals would otherwise be paid. For purposes of this Plan a
"Change in Control" shall be deemed to occur: (a) if any person (as
such term is used in Sections 13(d) and 14(d)(2) of the Exchange Act)
is or becomes the "beneficial owner" (as defined in Rule 13d-3 of the
Exchange Act), directly or indirectly, of securities of the Company
representing twenty percent (20%) or more of the combined voting power
of the Company's then outstanding securities; (b) upon the first
purchase of the Common Stock pursuant to a tender or exchange offer
(other than a tender or exchange offer made by the Company); (c) upon
the approval by the Company's stockholders of a merger or
consolidation, a sale, or disposition of all or substantially all the
Company's assets or a plan of liquidation or dissolution of the
Company; or (d) if, during any period of two (2) consecutive years,
individuals who at the beginning of such period constitute the Board
cease for any reason to constitute at least a majority thereof, unless
the election or nomination for the election by the Company's
stockholders of each new Director was approved by a vote of at least
two-thirds (2/3) of the Directors then still in office who were
Directors at the beginning of the period.
Notwithstanding the foregoing, a Change in Control shall not
be deemed to occur if the Company either merges or consolidates with or
into another company or sells or disposes of all or substantially all
of its assets to another company, if such merger, consolidation, sale
or disposition is in connection with a corporate restructuring wherein
the stockholders of the Company immediately before such merger,
consolidation, sale or disposition own, directly or indirectly,
immediately following such merger, consolidation, sale or disposition
at least eighty percent (80%) of the combined voting power of all
outstanding classes of securities of the
<PAGE> 2
company resulting from such merger or consolidation, or to which the
Company sells or disposes of its assets, in substantially the same
proportion as their ownership in the Company immediately before such
merger, consolidation, sale or disposition."
IN WITNESS WHEREOF, the Company has caused this amendment to be duly
executed on this 9th day of March, 1999.
EL PASO ENERGY CORPORATION
By: /s/ Joel Richards III
---------------------------------
Joel Richards III
Executive Vice President
Member of the Management
Committee
Attest:
/s/ David L. Siddall
- ---------------------------------------
Corporate Secretary
-2-
<TABLE> <S> <C>
<ARTICLE> 5
<LEGEND>
THIS SCHEDULE CONTAINS SUMMARY FINANCIAL INFORMATION EXTRACTED FROM CONSOLIDATED
STATEMENTS OF INCOME AND CONSOLIDATED BALANCE SHEETS.
</LEGEND>
<MULTIPLIER> 1,000,000
<S> <C>
<PERIOD-TYPE> 3-MOS
<FISCAL-YEAR-END> DEC-31-1999
<PERIOD-START> JAN-01-1999
<PERIOD-END> MAR-31-1999
<CASH> 90
<SECURITIES> 0
<RECEIVABLES> 780
<ALLOWANCES> 0<F1>
<INVENTORY> 48
<CURRENT-ASSETS> 1,223
<PP&E> 7,191
<DEPRECIATION> 0<F1>
<TOTAL-ASSETS> 10,466
<CURRENT-LIABILITIES> 1,935
<BONDS> 3,082
0
0
<COMMON> 377
<OTHER-SE> 1,785
<TOTAL-LIABILITY-AND-EQUITY> 10,466
<SALES> 0
<TOTAL-REVENUES> 1,494
<CGS> 0
<TOTAL-COSTS> 1,394
<OTHER-EXPENSES> 0
<LOSS-PROVISION> 0
<INTEREST-EXPENSE> 73
<INCOME-PRETAX> 117
<INCOME-TAX> 40
<INCOME-CONTINUING> 71
<DISCONTINUED> 0
<EXTRAORDINARY> 0
<CHANGES> (13)
<NET-INCOME> 58
<EPS-PRIMARY> .50<F2>
<EPS-DILUTED> 0.48
<FN>
<F1>Not separately identified in the Consolidated Financial Statements or
accompanying notes thereto.
<F2>Represents basic earnings per share.
</FN>
</TABLE>
